The Arctic is estimated to hold the world's largest remaining untapped gas reserves and some of its largest undeveloped oil reserves. These reserves, if tapped, may provide a local energy source for North America. However, the Arctic presents harsh physical conditions that make the production of oil in this environment particularly challenging, including extreme remoteness, ice, extreme low temperatures, and in winter long periods of darkness.
Other cold region deposits include the Athabasca oil sands in Northern Alberta with some 1.7 trillion bbls of bitumen in place—comparable in magnitude to the world's total proven reserves of conventional petroleum. However, the bitumen is too viscous to be produced in this cold environment, and must be heated and/or diluted with solvent before it will flow enough to be produced. The extreme cold temperatures and permafrost in Alaska and Canada contribute significantly to the cost and difficulty in the economical production of these reserves.
For example, one of the major costs involved in producing heavy oil in frigid areas is the cost of maintaining suitable temperature within the production tubing so that the production fluids can readily flow and be pumped to the surface. This is especially vital for that portion of the production tubing that passes through the permafrost. If the temperature within the tubing drops too much, especially during low flow or no flow (i.e. shut-in) conditions, the well fluids cool off and can become too viscous to flow or to be pumped through the tubing. In some cases, the oil can freeze solid within the tubing thereby creating a myriad of problems when the well is returned to full flow production.
Some of the common approaches used to address this problem include insulating the production tubing and/or the wellbore. Indeed, ConocoPhillips has invested significantly in well completions using vacuum insulated tubing, particularly in the vertical portions of steam assisted gravity drainage (SAGD) well pairs, where heat loss significantly increases steam costs.
Another solution is to displace the well fluids from the production tubing back into the wellbore and/or production formation with a non-freezing or anti-freeze fluid additive (e.g. methanol, diesel, or natural gas) during no-flow conditions.
Yet another solution is to strap an electrical, heat trace to the outside of the production tubing, thus heating the tubing to maintain its temperature.
Unfortunately, while each of these techniques may be applicable to particular situations, each may have serious drawbacks in others. For example, insulating the production tubing and/or the wellbore does not prevent freezing of the well fluids in the tubing, but only slows down the process. As to displacing the well fluids back out of the production tubing while production is shut-in, this process is normally expensive and labor intensive in that it must be carried out manually and can not be easily automated to “kick-in” only when needed. Finally, strapping the heat trace to the outside of the production tubing is grossly inefficient due to the amount of heat which is lost directly to the surrounding annulus in the wellbore and is unavailable for heating the inside of the production tubing. Thus, a large portion of the heat generated by an externally-mounted heat trace is immediately lost in the well annulus and is never conveyed to the inside of the production tubing where it needed.
Accordingly, it can be seen that a need continues to exist to automatically maintain the temperature inside the production tubing of a well that extends through a permafrost layer or other cold region at a desired temperature, which allows ready flow of produced fluids therethrough, especially during or after low- or no flow production rates.
U.S. Pat. No. 6,009,940 describes one possible solution, wherein a heating element is lowered down the production tubing and extends through at least the permafrost layer. Preferably, the heating element is a heat trace which is comprised of a commercially-available, electrical power cable of the type commonly used to supply electrical power to down-hole submersible, electrical well pumps. The lower ends of the leads within the cable are connected together to “short-circuit” the cable thereby converting the cable into an elongated, heating element.
A typical, short-circuited power cable of the type described above is capable of generating heat at a temperature of about 90° F. to about 150° F. under a predetermined load (e.g. 20 to 30 kilowatts per foot of tubing). While some of this generated heat radiates into and through the wall of tubing to heat the fluid flowing through the tubing, a large portion of this heat is lost into the annulus of well. Typically it is preferred to keep the temperature of the heavy oil flowing through the tubing at a temperature above 50° F. (e.g. between about 50° F. and about 70° F.) to insure ready flow therethrough. Thus, it can be seen that the load on the cable has to be substantial since the heating efficiency from the externally-mounted cable is extremely low.
U.S. Pat. No. 8,224,164 takes the idea further, deploying temperature limited heaters down-hole for various uses, which can be a mineral insulated (“MI”) cable. US20110017510 describes another MI heater cable, wherein the length of the cable is extended to reach further with electrical submersible pump (ESP) cable, which is much less expensive than MI cable.
Mineral-insulated copper-clad cable is a type of electrical cable made from copper conductors inside a copper sheath, insulated by inorganic magnesium oxide powder—the same type of heater used on older electric stove tops. The name is often abbreviated to MICC or MI cable, and colloquially known as “pyro” because the original manufacturer and vendor for this product was a company called Pyrotenax. A similar product sheathed with metals other than copper is called mineral insulated metal sheathed (MIMS) cable. By “MI cable” herein we mean to include both types.
MI cable is made by placing copper rods inside e.g., a circular copper tube and filling the intervening spaces with dry magnesium oxide powder. The overall assembly is then pressed between rollers to reduce its diameter (and increase its length). Up to seven conductors are often found in an MI cable, with up to 19 available from some manufacturers.
MI cable heaters have more optimum capabilities in various applications in the down-hole environment than polymer insulated heaters, i.e. higher temperature capability and higher power capabilities.
Further, since MI cables do not use organic material as insulation (except at the ends), they are more resistant to fires than plastic-insulated cables. MI cables are thus preferred in critical fire protection applications such as alarm circuits, fire pumps, and smoke control systems. MI cable is commonly used in industries that employ flammable fluids where small fires would otherwise cause damage to control or power cables. MI cable is also highly resistant to ionizing radiation and so finds applications in instrumentation for nuclear reactors and nuclear physics apparatus.
Because of its fire resistance, MI cable is particularly well suited for use in down-hole heaters, where fire can be catastrophic. However, the deployment of MI cable presents significant challenges, particularly when deployed into horizontal wells, used for example in steam assisted gravity drainage or “SAGD”, which are the most common well types in oil sand production.
In SAGD, typically two horizontal wells are placed deep in the pay—a producer well at the bottom of the pay, and an injector some 4-10 meters above and parallel to the producer. Steam is continuously injected into the injector, which forms a steam chamber. At the edges of the steam chamber, heat is transferred to the heavy oil, which melts, and the mobilized oil and condensed steam gravity drain to the producer.
An MI cable heater system was recently installed in a horizontal well on the North Slope of Alaska. Because much of the well was horizontal, gravity could not be used to deploy the cable along the horizontal portion. Instead, the MI cable was encapsulated in a length of coiled tubing prior to installation in the well, and this was then fed into the well, using the usual coiled tubing equipment and techniques.
In the oil and gas industries, “coiled tubing” refers to a very long metal pipe, normally 1″ to 3.25″ in diameter. It is used for interventions in oil and gas wells and sometimes as production tubing in depleted gas wells. The coiled tubing is a continuous length of steel or composite tubing that is flexible enough to be wound on a large reel for transportation. The coiled tubing unit is composed of a reel with the coiled tubing, an injector, control console, power supply and well-control stack. The coiled tubing is injected into the existing production string, unwound from the reel and inserted into the well.
Coiled tubing is chosen over conventional straight tubing because conventional tubing has to be screwed together. Additionally, coiled tubing does not require a workover rig. Because coiled tubing is inserted into the well while production is ongoing, it can be a cost-effective choice and can be used on high-pressure wells. Although a useful tool, coil tubing is a costly way of deploying down-hole tools, requiring additional personnel, space and equipment.
Further, CT conveyance has a limited reach. As the tube unspools, it passes through a gooseneck and chain-driven injector head that causes the continuous tubing to exceed its yield strength. This operation helps remove the residual curvature that the string developed while on the CT reel. However, the tubing still retains a small amount of curvature. This curvature, coupled with bends and deviations in the wellbore, puts the CT string in contact with the wellbore wall in many places, generating frictional resistance. As more and more tubing is pushed into the wellbore, the string wraps against the wall in a long helical loop, eventually resulting in “helical lockup,” where the CT tubing cannot be further pushed into the well.
Thus, there remains further need to develop and optimize methods for deploying MI cable in efficient manner. Preferably the method would not require CT tubing and could be both easily deployed as well as removed.